Rotary drill bits are commonly used for drilling wellbores in earth formations. One type of rotary drill bit is the fixed-cutter bit (often referred to as a “drag bit”), which typically includes a plurality of cutting elements secured to a face region of a bit body. The bit body of a rotary drill bit may be formed from steel. Alternatively, a bit body may be fabricated to comprise a composite material. A so-called “infiltration” bit includes a bit body comprising a particle-matrix composite material and is fabricated in a mold using an infiltration process. Recently, pressing and sintering processes have been used to form bit bodies of drill bits and other tools comprising particle-matrix composite materials. Such pressed and sintered bit bodies may be fabricated by pressing (e.g., compacting) and sintering a powder mixture that includes hard particles (e.g., tungsten carbide) and particles of a metal matrix material (e.g., a cobalt-based alloy, an iron-based alloy, or a nickel-based alloy).
A conventional earth-boring rotary drill bit 10 is shown in FIG. 1 that includes a bit body 12 comprising a particle-matrix composite material 15. The bit body 12 is secured to a steel shank 20 having a threaded connection portion 28 (e.g., an American Petroleum Institute (API) threaded connection portion) for attaching the drill bit 10 to a drill string (not shown). The bit body 12 includes a crown 14 and a steel blank 16. The steel blank 16 is partially embedded in the crown 14. The crown 14 includes a particle-matrix composite material 15, such as, for example, particles of tungsten carbide embedded in a copper alloy matrix material. The bit body 12 is secured to the steel shank 20 by way of a threaded connection 22 and a weld 24 extending around the drill bit 10 on an exterior surface thereof along an interface between the bit body 12 and the steel shank 20.
The bit body 12 further includes wings or blades 30 that are separated by junk slots 32. Internal fluid passageways (not shown) extend between the face 18 of the bit body 12 and a longitudinal bore 40, which extends through the steel shank 20 and partially through the bit body 12. Nozzle assemblies 42 also may be provided at the face 18 of the bit body 12 within the internal fluid passageways.
A plurality of cutting elements 34 is attached to the face 18 of the bit body 12. Generally, the cutting elements 34 of a fixed-cutter type drill bit have either a disk shape or a substantially cylindrical shape. A cutting surface 35 comprising a hard, super-abrasive material, such as polycrystalline diamond, may be provided on a substantially circular end surface of each cutting element 34. Such cutting elements 34 are often referred to as “polycrystalline diamond compact” (PDC) cutting elements 34. The PDC cutting elements 34 may be provided along the blades 30 within pockets 36 formed in the face 18 of the bit body 12, and may be supported from behind by buttresses 38, which may be integrally formed with the crown 14 of the bit body 12. Typically, the cutting elements 34 are fabricated separately from the bit body 12 and secured within the pockets 36 formed in the outer surface of the bit body 12. A bonding material such as an adhesive or, more typically, a metal alloy braze material may be used to secure the cutting elements 34 to the bit body 12.
During drilling operations, the drill bit 10 is secured to the end of a drill string, which includes tubular pipe and equipment segments coupled end-to-end between the drill bit 10 and other drilling equipment at the surface. The drill bit 10 is positioned at the bottom of a wellbore such that the cutting elements 34 are adjacent the earth formation to be drilled. Equipment such as a rotary table or top drive may be used for rotating the drill string and the drill bit 10 within the borehole. Alternatively, the shank 20 of the drill bit 10 may be coupled directly to a drive shaft of a downhole motor, which then may be used to rotate the drill bit 10. As the drill bit 10 is rotated, drilling fluid is pumped to the face 18 of the bit body 12 through the longitudinal bore 40 and the internal fluid passageways (not shown). Rotation of the drill bit 10 under weight applied through the drill string causes the cutting elements 34 to scrape across and shear away the surface of the underlying formation. The formation cuttings mix with and are suspended within the drilling fluid and pass through the junk slots 32 and the annular space between the wellbore and the drill string to the surface of the earth formation.
Conventionally, bit bodies that include a particle-matrix composite material 15, such as the previously described bit body 12, have been fabricated in graphite molds using the so-called “infiltration” process. The cavities of the graphite molds are conventionally machined with a multi-axis machine tool. Fine features are then added to the cavity of the graphite mold using hand-held tools. Additional clay work also may be required to obtain the desired configuration of some features of the bit body. Where necessary, preform elements or displacements (which may comprise ceramic components, graphite components, or resin-coated sand compact components) may be positioned within the mold and used to define the internal passages, cutting element pockets 36, junk slots 32, and other external topographic features of the bit body 12. The cavity of the graphite mold is filled with hard particulate carbide material (such as tungsten carbide, titanium carbide, tantalum carbide, etc.). The preformed steel blank 16 may then be positioned in the mold at the appropriate location and orientation. The steel blank 16 typically is at least partially submerged in the particulate carbide material within the mold.
The mold then may be vibrated or the particles otherwise packed to decrease the amount of space between adjacent particles of the particulate carbide material. A matrix material (often referred to as a “binder” material), such as a copper-based alloy, may be melted, and caused or allowed to infiltrate the particulate carbide material within the mold cavity. The mold and bit body 12 are allowed to cool to solidify the matrix material. The steel blank 16 is bonded to the particle-matrix composite material 15 forming the crown 14 upon cooling of the bit body 12 and solidification of the matrix material. Once the bit body 12 has cooled, the bit body 12 is removed from the mold and any displacements are removed from the bit body 12. Destruction of the graphite mold typically is required to remove the bit body 12 therefrom.
After the bit body 12 has been formed, PDC cutting elements 34 may be bonded to the face 18 of the bit body 12 by, for example, brazing, mechanical, or adhesive affixation. Alternatively, the cutting elements 34 may be bonded to the face 18 of the bit body 12 during furnacing of the bit body if thermally stable synthetic diamonds, or natural diamonds, are employed in the cutting elements 34. Of course, more than one type of cutting element may be employed, as is known to those of ordinary skill in the art.
The bit body 12 may be secured to the steel shank 20. As the particle-matrix composite materials 15 typically used to form the crown 14 are relatively hard and not easily machined, the steel blank 16 is used to secure the bit body 12 to the shank 20. Complementary threads may be machined on exposed surfaces of the steel blank 16 and the shank 20 to provide the threaded connection 22 therebetween. The steel shank 20 may be threaded onto the bit body 12, and the weld 24 then may be provided along the interface between the steel blank 16 and the steel shank 20.
As discussed above, nozzle assemblies 42 also may be provided at the face 18 of the bit body 12. Nozzle assemblies 42 allow fluid flow areas to be specified or selected to obtain various flow rates and patterns. During drilling, drilling fluid is discharged through nozzle assemblies 42 located in nozzle ports in fluid communication with the face 18 of bit body 12 for cooling the cutting surface 35 of cutting elements 34 and removing formation cuttings from the face 18 of drill bit 10 into passages such as junk slots 32. As shown in FIG. 2 of the drawings, a conventional earth-boring rotary drill bit 10 for use in subterranean drilling may include a plurality of nozzle assemblies, exemplified by illustrated nozzle assembly 42. While many conventional drill bits use a single piece nozzle, the nozzle assembly 42 is a two piece replaceable nozzle assembly, the first piece being a tubular tungsten carbide inlet tube 50 that fits into a port or passage 54 formed in the body 12 of the drill bit 10, and is seated upon an annular shoulder 56 of passage 54. The second piece is a tungsten carbide nozzle 52 that may have a restricted bore 64 that is secured within passage 54 of the drill bit 10 by threads that engage mating threads 58 on the wall of passage 54. The inlet tube 50 is retained in passage 54 by abutment between the annular shoulder 56 and the interior end of the nozzle 52. The inlet tube 50 and the nozzle 52 are used to provide protection to the material of the drill bit 10 through which passage 54 extends against erosive drilling fluid effects by providing a hard, abrasion- and erosion-resistant pathway from a fluid passageway 68 within the bit body to a nozzle exit 60 located proximate to an exterior surface of the bit body. The inlet tube 50 and nozzle 52 are replaceable should the drilling fluid erode or wear the parts within internal passage 62 extending through these components, or when a nozzle 52 having a different orifice size is desired. The outer surface or wall of the nozzle 52 is in sealing contact with a compressed O-ring 66 disposed in an annular groove formed in the wall of passage 54 to provide a fluid seal between the bit body 12 and the nozzle 52.